Impregnated drag bits are used conventionally for drilling hard and/or abrasive rock formations, such as sandstones. These impregnated drill bits typically employ a cutting face composed of superabrasive cutting particles, such as natural or synthetic diamond grit, dispersed within a matrix of wear-resistant material. As such a bit drills, the matrix and embedded diamond particles wear, worn cutting particles are lost and new cutting particles are exposed. These diamond particles may either be natural or synthetic and may be cast integral with the body of the bit, as in low-pressure infiltration, or may be preformed separately, as in hot isostatic pressure infiltration, and attached to the bit by brazing or furnaced to the bit body during manufacturing thereof by an infiltration process.
Conventional impregnated bits generally exhibited a poor hydraulics design by employing a crow's foot to distribute drilling fluid across the bit face and providing only minimal flow area. Further, conventional impregnated bits did not drill effectively when the bit encountered softer and less abrasive layers of rock, such as shales. When drilling through shale, or other soft formations, with a conventional impregnated drag bit, the cutting structure tended to quickly clog or “ball up” with formation material, making the drill bit ineffective. The softer formations can also plug up fluid courses formed in the drill bit, causing heat buildup and premature wear of the bit. Therefore, when shale-type formations were encountered, a more aggressive bit was desired to achieve a higher rate-of-penetration (ROP). It followed, therefore, that selection of a bit for use in a particular drilling operation became more complicated when it was expected that formations of more than one type would be encountered during the drilling operation.
Moreover, during the drilling of a well bore, the well may be drilled in multiple sections wherein at least one section is drilled followed by the cementing of a tubular metal casing within the borehole. In some instances, several sections of the well bore may include casing of successively smaller sizes, or a liner may be set in addition to the casing. In cementing the casing (such term including a liner) within the borehole, cement is conventionally disposed within an annulus defined between the casing and the borehole wall by flowing the cement downwardly through the casing to the bottom thereof and then displacing the cement through a so-called “float shoe” such that it flows back upwardly through the annulus. Such a process conventionally results in a mass or section of hardened cement proximate the float shoe and formed at the lower extremity of the casing. Thus, in order to drill the well bore to further depths, it becomes necessary to first drill through the float shoe and mass of cement.
Conventionally, the drill bit used to drill out the cement and float shoe did not exhibit the desired design for drilling the subterranean formation, which lies therebeyond. Those drilling the well bore were then often faced with the decision of changing out drill bits after the cement and float shoe had been penetrated or, alternatively, continuing with a drill bit that may not have been optimized for drilling the subterranean formation below the casing.
Thus, it was recognized as beneficial to design a drill bit that would perform more aggressively in softer, less abrasive formations while also providing adequate ROP in harder, more abrasive formations and for drilling such formations interbedded with soft and nonabrasive layers without requiring increased weight-on-bit (WOB) during the drilling process.
Additionally, it was also recognized as advantageous to provide a drill bit with “drill out” features to enable the drill bit to drill through a cement shoe and continue drilling the subsequently encountered subterranean formation in an efficient manner.
To address these needs, inventors of the assignee of the present disclosure developed and implemented a number of superior bit designs offered as HEDGEHOG® impregnated bits. A variety of structures for such bits and specific features thereof are disclosed and claimed in U.S. Pat. Nos. 6,510,906; 6,843,333; 7,278,499; 7,497,280; 7,730,976; 8,191,657; 8,220,567 and 8,333,814 and in U.S. Patent Publications 2010/0122848; 2010/0219000; and 2011/0061943, among others. The disclosure of each of the foregoing patents and patent publications is hereby incorporated herein in its entirety by this reference.
Notable features of the HEDGEHOG® impregnated bits include the use of impregnated cutting structures protruding above the bit face to an exposure far greater than was previously conventional and formed as posts, the use of nozzles and of relatively deep and wide fluid passages and junk slots for improved bit hydraulics, the use of polycrystalline diamond compact cutting elements in the bit cone for superior performance in interbedded and shaley formations, as well as the use of thermally stable polycrystalline diamond cutting elements in combination with impregnated posts and other impregnated cutting structures for enhanced drill out capability.
However, even such bits conventionally require a “break-in” period before attaining optimum performance, since the superabrasive particles in the as-formed cutting structures are substantially embedded in the matrix material of the cutting structure. Thus, in operation, a conventional impregnated bit would be run into a well and “broken-in” or “sharpened” by drilling into an abrasive formation at a selected WOB as the bit is rotated. For the first several feet of penetration, the diamond grit on the ends of the posts or other cutting structures becomes more exposed by wear of the relatively softer matrix material, as no substantial volume of diamond is usually exposed on an impregnated cutting structure as manufactured. As the bit is “sharpened” to enhance exposure of the diamond grit on formation-engaging surfaces of the impregnated cutting structures, ROP increases and stabilizes. It has been demonstrated that HEDGEHOG® impregnated bits, once broken in, exhibit an increased ROP over conventional impregnated bits. It has likewise been shown that HEDGEHOG® impregnated bits exhibit a substantially similar ROP to that of a conventional impregnated bit but at a reduced WOB.
However, the need to break in impregnated bits to achieve their full potential in terms of increased ROP and reduced required WOB is undesirable.